The invention relates generally to calibration of sensors. More specifically, the invention relates to an improved method for calibrating sensors adapted for measurement of subsurface properties.
In the oil-drilling and exploration industry, many types of sensors are used to evaluate subsurface formations traversed by a borehole, commonly referred to as well logging. Sensors measure a phenomenon that is related to a physical property of the formation, such as the density or the porosity. A particular formation property can be determined by measuring a phenomenon related to the formation property and calculating the formation property based on the relationship between the measured phenomenon and the desired formation property. In order to obtain useful information about the formation property, it is necessary to calibrate the sensor.
Calibration normalizes a raw measurement to a known reference. A sensor is used to measure a substance with known properties. The calibration measurement made by the sensor can be correlated to the known properties of the substance. This determines the relationship between the raw sensor measurement and the physical property.
One example of a sensor used in well logging is a density sensor. One type of density sensor uses a radioactive source to emit gamma rays into a formation. Some of the emitted gamma rays interact with electrons in the formation, and, through a process called Compton Scattering, are scattered back into the borehole. The density sensor includes detectors that detect gamma rays scattered back into the borehole. The number of gamma rays that scatter back into the borehole is related to the number of electrons in the formation, and the number of electrons in the formation is related to the density of the formation. Thus, the number of detected gamma rays, called the count rate, is related to the density of the formation.
Calibration is required because the number of detected gamma rays depends on more factors than the density of the formation. The count rate also depends heavily on the strength of the source and the sensor geometry. For example, it is expected that by doubling the activity of the source, i.e. changing to a source that emits twice as many gamma rays, the count rate would also double. Further, the sensor efficiency at detecting gamma rays affects the count rate. This efficiency varies from sensor to sensor. By calibrating a density sensor, the density of a formation can be precisely determined based on the count rate measured by the sensor.
Typical calibration methods are performed on a sensor before it is disposed within a borehole. Often times, these calibration methods are performed in a controlled environment away from the well site. One common method of calibrating a density sensor includes placing the sensor in water, inserting a source into the sensor, and measuring the count rate of back-scattered gamma rays. The count rate made with the sensor in water is correlated to the density of water, and the slope of the response function is assumed. This method is known in the art as a “one-point method”, because a calibration line is determined based on a single point.
FIG. 1A shows a plot of a prior art response function 101 for a density sensor with a water calibration point 102. Typical calibration methods assume the density sensor has a linear response with a known slope. With the water calibration point and an assumed slope, a sensor response function, plotted at 101, can be determined as the line with the assumed slope that intersects the water calibration point 102.
Another sensor used in well logging is a neutron sensor. A neutron sensor uses a source that emits “fast”, or high energy, neutrons into a formation. The neutrons lose energy through collisions with the atoms in the formation, becoming “thermal” or “epi-thermal” neutrons. The neutron sensor detects these neutrons that migrate back into the borehole.
The fast neutrons slow down by colliding with atoms in the formation. Hydrogen, because it has a mass similar to that of a neutron, provides much more rapid slowing of the neutrons than other atoms. Thus, the number of thermal neutrons detected in a borehole is related to the number of hydrogen atoms in the formation. Because water and hydrocarbons have similar concentrations of hydrogen (hydrogen indices), and because the rock matrix of the formation is relatively free of hydrogen, the number of thermal neutrons in the borehole is related to the amount of hydrocarbons and water in the formation. In a non-gas bearing formation, the volume fraction of water and hydrocarbons is called the porosity.
Calibration of a neutron sensor determines how the thermal neutron count rate is related to the formation porosity. One conventional method includes surrounding the neutron sensor with water and making a calibration measurement. In this type of calibration, the porosity of water is set at one.
FIG. 1B shows a prior art neutron calibration with water. The sensor is assumed to have a linear response with a known slope, and the measurement of the count rate at the water point 112 yields a response function, plotted at 111, that intersects the water point 112.